DATOS TILES HEAT TRANSFER

10 / 450 R E B O I L E R S

Table 10.2 Recommended Fouling Factors for Reboiler Design

Boiling-side stream Fouling factor (h ft2 F/Btu)C1C8 normal hydrocarbons 00.001Heavier normal hydrocarbons 0.0010.003Diolefins and polymerizing hydrocarbons 0.0030.005

Heating-side stream

Condensing steam 00.0005Condensing organic 0.00050.001Organic liquid 0.00050.002

Source: Ref. [5]

21 Heat Exchangers

Table 1 Heat Exchanger Selection Criteria [5]

Air Spiral Plate Coiled Double Scraped Shell Criteria cooled Plate plate Lamella fin tube pipe Graphite surface and tube

Pressure psi 6000 300 (4) 250 (7) 600 loo0 1000 600 150 600 (18) 8000 150 (11)

Temperature O F (1) 500 (4) 750 1000 150 (12) 900 1000 (16) 600 loo0 750 (13)

Max ft2/unit none 16OOO/frame 3000 loo00 1 m (12) 200000 300 (14) (17) 10 30000/shell 500 (13)

Compactness *(2) **** **** ** ***** **** * *** * * ** ***** **** ** * * *** * *** ***Mech. cleaning ** **** **** *** ** *** *** ***** **** ***Chem.

**** ** * * **C0st/ft2 ** ** ***

(10) ***** ** *****

**** ( 5 ) *** ****

(8) * * *** * ** **Maintenance ease

*** **** **** **** *** **** **** ***** *** **Corrosion risk Fouling risk ** ***** **** *** ** *** *** *** ***** * (18) Fouling effect

** * (3) **** **** ** * ** *** ** **** (18) **

** Leakage risk * (6) * (9) ** **** *** *** (15) * ** (22) Duty changes after

** **** * * *** ** * *** * *installation Temp. cross * **** **** *** ***** ***** *** *** *** **

* **** **** ** ***** ** ** **** *** *Viscous flow *** (23)

** **** **** ** *** ** ** *** ***** *Heat sensitive fluids (19) Solids flowing * ** **** ** * * *** * ***** (20) * **** * *** *** **** **** **** *** * ****Gases Phase change **** * **** *** **** **** **** *** ***** (21) ****

*** *** * ** ***** **** * *** * **Multi fluid exchange

*Very poor; **poor; ***fair; ****good; *****very good. Notes: ( I ) use restricted to temperatures from ambient to around 300F; (2) often mounted high or above pipe racks; (3) fouling on outside can reduce air flow and diminish MTD; (4) depends on gasket material; (5) low relative cost applies to non-ferrous materials; (6)plate edges can be seal welded but dismantling then very difficult; (7) for diameters up to 1 meter. For larger diameters the pressure limit is lower; (8) in all metals; (9) see (6); (10) available only in nonferrous materials; ( I 1 ) applies to reversing service in aluminum; (12) in aluminum; ( 1 3) in nonferrous, nonaluminum materials; (14) above 300 ft' shell and tube exchangers are usually cheaper; (15) if all welded; (16) 400F for liquids, up to 1500F for some gases; (17) 300 ft' for cubic block; 2000 ft' for modular block; (18) applies to scraped inside; (19) high speed rotor; (20) low speed rotor; (21) liquid to solid. or liquid to vapor; (22) depends on TEMA type; and (23) applies to viscous fluids being heated on shellside.

248 Chapter 5

Pa &-A

.Pass(--J6

A-A .Fro& view

U 0-0.Rear vtew

A-A

A- A 8 - 8

6@ PASSQ* B- 8

p u sSA - A 8 - 8 A - A

Pu 8 - 8

Figure 19 Typical tubeside partitions for multipass arrangement. (a) U-tube; and (b) straight tubes.

9.1 Drains and Vents All exchangers need to be drained and vented; therefore, care should be taken to properly locate and size drains and vents. Additional openings may be required for instruments such as pressure gages and thermocouples.

B.W.G. Chart

This chart provides a cross reference between B.W.G. (Birmingham Wire Gauge), imperial sizes and metric equivalents, in terms of tube wall thickness.

B.W.G. inches mm

0 0.340 8.636

1 0.300 7.620

2 0.284 7.214

3 0.259 6.579

4 0.238 6.045

5 0.220 5.588

6 0.203 5.156

7 0.180 4.572

8 0.165 4.191

B.W.G. inches mm

9 0.148 3.759

10 0.134 3.404

11 0.120 3.048

12 0.109 2.769

13 0.095 2.413

14 0.083 2.108

15 0.072 1.829

16 0.065 1.651

17 0.058 1.473

B.W.G. inches mm

18 0.049 1.245

19 0.042 1.067

20 0.035 0.889

21 0.032 0.813

22 0.028 0.711

23 0.025 0.635

24 0.022 0.559

25 0.020 0.508

Tweelingenlaan 142 7324 BP Apeldoorn The Netherlands Tel: +31 - (0)55 58 22 370 Fax: +31 - (0)55 58 22 380 info@wolverine-tube.nl www.wolverine-tube.nl

H E AT E X C H A N G E R S 3 / 95

Table 3.3 Typical Values of Fouling Factors (h ft2 F/Btu)Cooling water streamsa

Seawater 0.00050.001 Brackish water 0.0010.002 Treated cooling tower water 0.0010.002 Municipal water supply 0.0010.002 River water 0.0010.003 Engine jacket water 0.001 Distilled or demineralized water 0.0005 Treated boiler feedwater 0.00050.001 Boiler blowdown 0.002

Service gas streams

Ambient air (in air-cooled units) 00.0005 Compressed air 0.0010.002 Steam (clean) 00.0005 Steam (with oil traces) 0.0010.002 Refrigerants (with oil traces) 0.002 Ammonia 0.001 Carbon dioxide 0.002 Flue gases 0.0050.01

Service liquid streams

Fuel oil 0.0020.005 Lubrication oil 0.001 Transformer oil 0.001 Hydraulic fluid 0.001 Organic heat-transfer fluids 0.0010.002 Refrigerants 0.001 Brine 0.003

Process gas streams

Hydrogen 0.001 Organic solvent vapors 0.001 Acid gases 0.0020.003 Stable distillation overhead products 0.001

Process liquid streams

Amine solutions 0.002 Glycol solutions 0.002 Caustic solutions 0.002 Alcohol solutions 0.002 Ammonia 0.001 Vegetable oils 0.003 Stable distillation side-draw and bottom products 0.0010.002

Natural gas processing streams

Natural gas 0.001 Overhead vapor products 0.0010.002 C3 or C4 vapor (condensing) 0.001 Lean oil 0.002 Rich oil 0.001 LNG and LPG 0.001

(Continued)

3 / 96 H E AT E X C H A N G E R S

Table 3.3 (Continued)Oil refinery streams

Crude oilb Temperature less than 250F 0.0020.003 Temperature between 250F and 350F 0.0030.004 Temperature between 350F and 450F 0.0040.005 Temperature greater than 450F 0.0050.006

Liquid product streams Gasoline 0.0010.002 Naphtha and light distillates 0.0010.003 Kerosene 0.0010.003 Light gas oil 0.0020.003 Heavy gas oil 0.0030.005 Heavy fuel oils 0.0030.007 Asphalt and residuum 0.0070.01

Other oil streams Refined lube oil 0.001 Cycle oil 0.0020.004 Coker gas oil 0.0030.005 Absorption oils 0.002

aAssumes water velocity greater than 3 ft/s. Lower values of ranges correspond to water temperature below about 120Fand hot stream temperature below about 250F.bAssumes desalting at approximately 250F and a minimum oil velocity of 2 ft/s.Source: Refs. [7,8] and www.engineeringpage.com.

DecompositionSome organic compounds may decompose when they are heated or come in contact with ahot surface, forming carbonaceous deposits such as coke and tar. In cracking furnaces, partialdecomposition of the hydrocarbon feedstock is the objective and coke formation is an undesiredbut unavoidable result. PolymerizationPolymerization reactions can be initiated when certain unsaturated organic compounds areheated or come in contact with a hot metal tube wall. The resulting reaction products canform a very tough plastic-like layer that can be extremely difficult to remove from heat-transfersurfaces. SedimentationSedimentation fouling results from the deposition of suspended solids entrained in many pro-cess streams such as cooling water and flue gases. High fluid velocities tend to minimize theaccumulation of deposits on heat-transfer surfaces. Biological activityBiological fouling is most commonly caused bymicro-organisms, althoughmacroscopic marineorganisms can sometimes cause problems as well. Cooling water and some other processstreams may contain algae or bacteria that can attach and grow on heat-transfer surfaces, form-ing slimes that are very poor heat conductors. Metabolic products of these organisms can alsocause corrosion of metal surfaces. Biocides and copper-nickel alloy tubing can be used to inhibitthe growth of micro-organisms and mitigate this type of fouling.

It can be seen from Table 3.3 that the range of values of fouling factors spans more than an order ofmagnitude. For very clean streams, values of 0.0005 h ft2 F/Btu or less are appropriate, whereasvery dirty streams require values of 0.0050.01 h ft2 F/Btu. However, values in the range 0.0010.003 h ft2 F/Btu are appropriate for the majority of cases.

H E AT E X C H A N G E R S 3 / 107

Table 3.5 Typical Values of Overall Heat-Transfer Coefficients in Tubular Heat Exchangers.U=Btu/h ft2 FShell side Tube side Design U Includes total dirt

Liquidliquid media

Aroclor 1248 Jet fuels 100150 0.0015Cutback asphalt Water 1020 0.01Demineralized water Water 300500 0.001Ethanol amine (MEA or Water or DEA, or 140200 0.003DEA) 1025% solutions MEA solutionsFuel oil Water 1525 0.007Fuel oil Oil 1015 0.008Gasoline Water 60100 0.003Heavy oils Heavy oils 1040 0.004Heavy oils Water 1550 0.005Hydrogen-rich reformer Hydrogen-rich reformer 90120 0.002stream streamKerosene or gas oil Water 2550 0.005Kerosene or gas oil Oil 2035 0.005Kerosene or jet fuels Trichloroethylene 4050 0.0015Jacket water Water 230300 0.002Lube oil (low viscosity) Water 2550 0.002Lube oil (high viscosity) Water 4080 0.003Lube oil Oil 1120 0.006Naphtha Water 5070 0.005Naphtha Oil 2535 0.005Organic solvents Water 50150 0.003Organic solvents Brine 3590 0.003Organic solvents Organic solvents 2060 0.002Tall oil derivatives, Water 2050 0.004vegetable oil, etc.Water Caustic soda 100250 0.003

solutions (1030%)Water Water 200250 0.003Wax distillate Water 1525 0.005Wax distillate Oil 1323 0.005

Condensing vaporliquid media

Alcohol vapor Water 100200 0.002Asphalt (450F.) Dowtherm vapor 4060 0.006Dowtherm vapor Tall oil and derivatives 6080 0.004Dowtherm vapor Dowtherm liquid 80120 0.0015Gas-plant tar Steam 4050 0.0055High-boiling hydrocarbons V Water 2050 0.003Low-boiling hydrocarbons A Water 80200 0.003Hydrocarbon vapors Oil 2540 0.004(partial condenser)Organic solvents A Water 100200 0.003Organic solvents high NC, A Water or brine 2060 0.003Organic solvents low NC, V Water or brine 50120 0.003Kerosene Water 3065 0.004Kerosene Oil 2030 0.005Naphtha Water 5075 0.005

(Continued)

3 / 108 H E AT E X C H A N G E R S

Table 3.5 (Continued)Shell side Tube side Design U Includes total dirt

Naphtha Oil 2030 0.005Stabilizer reflux vapors Water 80120 0.003Steam Feed water 4001000 0.0005Steam No. 6 fuel oil 1525 0.0055Steam No. 2 fuel oil 6090 0.0025Sulfur dioxide Water 150200 0.003Tall-oil derivatives, vegetable Water 2050 0.004oils (vapor)Water Aromatic vapor-stream 4080 0.005

azeotrope

Gasliquid media

Air, N2, etc. (compressed) Water or brine 4080 0.005Air, N2, etc., A Water or brine 1050 0.005Water or brine Air, N2 (compressed) 2040 0.005Water or brine Air, N2, etc., A 520 0.005Water Hydrogen containing 80125 0.003

naturalgas mixtures

Vaporizers

Anhydrous ammonia Steam condensing 150300 0.0015Chlorine Steam condensing 150300 0.0015Chlorine Light heat-transfer oil 4060 0.0015Propane, butane, etc. Steam condensing 200300 0.0015Water Steam condensing 250400 0.0015

NC: non-condensable gas present; V: vacuum; A: atmospheric pressure.Dirt (or fouling factor) units are (h)(ft2)(F)/BtuSource: Ref. [1].

For the purpose of making a preliminary cost estimate, determine the required heat-transfer areaof the exchanger.

Solution(a) Calculate the heat load and outlet oil temperature by energy balances on the two streams.

q = (m CPT )K = 30, 000 0.6 (400 250)q = 2.7 106 Btu/hq = 2.7 106 = (m CPT )oil = 75, 000 0.05 (T 110)T = 182F

(b) Calculate the LMTD.

T = 140F{110F 182F250F 400F

}T = 218F

(T1n)cf =218 140

ln (218/140)= 176F

3 / 100 H E AT E X C H A N G E R S

Solution

R = Ta Tbtb ta

= 100 160150 230 = 0.75

P = tb taTa ta

= 150 230100 230 = 0.615

From Figure 3.9 (or Equation (3.15)), F = 0.72. Since F is less than 0.8, a 1-2 exchanger shouldnot be used. However, with two shell passes, it is found from Figure 3.10 that F = 0.94. Hence,an exchanger with two shell passes and a multiple of four tube passes will be suitable. Such anexchanger is called a 24 exchanger. The mean temperature difference in the exchanger is easily

ta

tb

Ta

Tb

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.00.5

0.6

0.7

0.8

0.9

1.0

F 15.020.0

R

10.08.0

6.0

4.0

2.5

3.0 2.01.81.6

1.4

1.2 1.0 0.90.80.7

0.6

0.5

0.4

0.3

0.2

0.1

P

Figure 3.9 LMTD correction factor for 12 exchangers (Source: Ref. [8]).

10 / 448 R E B O I L E R S

For reliable design and operation, the vapor weight fraction in thermosyphon reboilers shouldbe limited to about 2530% for organic compounds and about 10% for water and aqueous solutions[1,2]. If these limits cannot be attained with once-through operation, then a recirculating systemshould be used.

10.2.7 Reboiler selectionIn some applications the choice of reboiler type is clear-cut. For example, severely fouling or veryviscous liquids dictate a forced flow reboiler. Similarly, a dirty or corrosive heatingmedium togetherwith a moderately fouling process stream favors a horizontal thermosyphon reboiler. In most appli-cations, however, more than one type of reboiler will be suitable. In these situations the selection isusually based on considerations of economics, reliability, controllability, and experience with sim-ilar services. The guidelines presented by Palen [1] and reproduced in Table 10.1 provide usefulinformation in this regard. Kister [3] also gives a good concise comparison of reboiler types andthe applications in which each is preferred.Sloley [2] surveyed the use of vertical versus horizontal thermosyphon reboilers in the petroleum

refining, petrochemical and chemical industries. Of the thermosyphons used in petroleum refining,95% are horizontal units; in the petrochemical industry, 70% are vertical units; and in the chemicalindustry, nearly 100% are vertical units. He attributes this distribution to two factors, size andfouling tendency. For the relatively small, clean services typical of the chemical industry, verticalthermosyphons are favored, whereas the large and relatively dirty services common in petroleumrefining dictate horizontal thermosyphons. Services in the petrochemical industry also tend to be

Table 10.1 Guidelines for Reboiler Selection

Process conditions Reboiler type

Kettle or Horizontal Vertical Forcedinternal shell-side tube-side flow

thermosyphon thermosyphon

Operating pressureModerate E G B ENear critical B-E R Rd EDeep vacuum B R Rd EDesign TModerate E G B ELarge B R G-Rd ESmall (mixture) F F Rd PVery small (pure component) B F P PFoulingClean G G G EModerate Rd G B EHeavy P Rd B GVery heavy P P Rd BMixture boiling rangePure component G G G ENarrow G G B EWide F G B EVery wide, with viscous liquid F-P G-Rd P B

Category abbreviations: B: best; G: good operation; F: fair operation, but better choice is possible; Rd: risky unless carefullydesigned, but could be best choice in some cases; R: risky because of insufficient data; P: poor operation; and E: operablebut unnecessarily expensive.Source: Ref. [1]

10/528

RE

BO

ILER

S

Appendix 10.A Areas of Circular Segments.

h/D A h/D A h/D A h/D A h/D A h/D A h/D A h/D A h/D A h/D A

0.050 0.01468 0.100 0.04087 0.150 0.07387 0.200 0.11182 0.250 0.15355 0.300 0.19817 0.350 0.24498 0.400 0.29337 0.450 0.342780.002 0.00012 0.052 0.01556 0.102 0.04208 0.152 0.07531 0.202 0.11343 0.252 0.15528 0.302 0.20000 0.352 0.24689 0.402 0.29533 0.452 0.344770.004 0.00034 0.054 0.01646 0.104 0.04330 0.154 0.07675 0.204 0.11504 0.254 0.15702 0.304 0.20184 0.354 0.24880 0.404 0.29729 0.454 0.346760.006 0.00062 0.056 0.01737 0.106 0.04452 0.156 0.07819 0.206 0.11665 0.256 0.15876 0.306 0.20368 0.356 0.25071 0.406 0.29926 0.456 0.348760.008 0.00095 0.058 0.01830 0.108 0.04576 0.158 0.07965 0.208 0.11827 0.258 0.16051 0.308 0.20553 0.358 0.25263 0.408 0.30122 0.458 0.35075

0.010 0.00133 0.060 0.01924 0.110 0.04701 0.160 0.08111 0.210 0.11990 0.260 0.16226 0.310 0.20738 0.360 0.25455 0.410 0.30319 0.460 0.352740.012 0.00175 0.062 0.02020 0.112 0.04826 0.162 0.08258 0.212 0.12153 0.262 0.16402 0.312 0.20923 0.362 0.25647 0.412 0.30516 0.462 0.354740.014 0.00220 0.064 0.02117 0.114 0.04953 0.164 0.08406 0.214 0.12317 0.264 0.16578 0.314 0.21108 0.364 0.25839 0.414 0.30712 0.464 0.356730.016 0.00268 0.066 0.02215 0.116 0.05080 0.166 0.08554 0.216 0.12481 0.266 0.16755 0.316 0.21294 0.366 0.26032 0.416 0.30910 0.466 0.358730.018 0.00320 0.068 0.02315 0.118 0.05209 0.168 0.08704 0.218 0.12646 0.268 0.16932 0.318 0.21480 0.368 0.26225 0.418 0.31107 0.468 0.36072

0.020 0.00375 0.070 0.02417 0.120 0.05338 0.170 0.08854 0.220 0.12811 0.270 0.17109 0.320 0.21667 0.370 0.26418 0.420 0.31304 0.470 0.362720.022 0.00432 0.072 0.02520 0.122 0.05469 0.172 0.09004 0.222 0.12977 0.272 0.17287 0.322 0.21853 0.372 0.26611 0.422 0.31502 0.472 0.364710.024 0.00492 0.074 0.02624 0.124 0.05600 0.174 0.09155 0.224 0.13144 0.274 0.17465 0.324 0.22040 0.374 0.26805 0.424 0.31699 0.474 0.366710.026 0.00555 0.076 0.02729 0.126 0.05733 0.176 0.09307 0.226 0.13311 0.276 0.17644 0.326 0.22228 0.376 0.26998 0.426 0.31897 0.476 0.368710.028 0.00619 0.078 0.02836 0.128 0.05866 0.178 0.09460 0.228 0.13478 0.278 0.17823 0.328 0.22415 0.378 0.27192 0.428 0.32095 0.478 0.37071

0.030 0.00687 0.080 0.02943 0.130 0.06000 0.180 0.09613 0.230 0.13646 0.280 0.18002 0.330 0.22603 0.380 0.27386 0.430 0.32293 0.480 0.372700.032 0.00756 0.082 0.03053 0.132 0.06135 0.182 0.09767 0.232 0.13815 0.282 0.18182 0.332 0.22792 0.382 0.27580 0.432 0.32491 0.482 0.374700.034 0.00827 0.084 0.03163 0.134 0.06271 0.184 0.09922 0.234 0.13984 0.284 0.18362 0.334 0.22980 0.384 0.27775 0.434 0.32689 0.484 0.376700.036 0.00901 0.086 0.03275 0.136 0.06407 0.186 0.10077 0.236 0.14154 0.286 0.18542 0.336 0.23169 0.386 0.27969 0.436 0.32887 0.486 0.378700.038 0.00976 0.088 0.03387 0.138 0.06545 0.188 0.10233 0.238 0.14324 0.288 0.18723 0.338 0.23358 0.388 0.28164 0.438 0.33086 0.488 0.38070

0.040 0.01054 0.090 0.03501 0.140 0.06683 0.190 0.10390 0.240 0.14494 0.290 0.18905 0.340 0.23547 0.390 0.28359 0.440 0.33284 0.490 0.382700.042 0.01133 0.092 0.03616 0.142 0.06822 0.192 0.10547 0.242 0.14666 0.292 0.19086 0.342 0.23737 0.392 0.28554 0.442 0.33483 0.492 0.384700.044 0.01214 0.094 0.03732 0.144 0.06963 0.194 0.10705 0.244 0.14837 0.294 0.19268 0.344 0.23927 0.394 0.28750 0.444 0.33682 0.494 0.386700.046 0.01297 0.096 0.03850 0.146 0.07103 0.196 0.10864 0.246 0.15009 0.296 0.19451 0.346 0.24117 0.396 0.28945 0.446 0.33880 0.496 0.388700.048 0.01382 0.098 0.03968 0.148 0.07245 0.198 0.11023 0.248 0.15182 0.298 0.19634 0.348 0.24307 0.398 0.29141 0.448 0.34079 0.498 0.390700.050 0.01468 0.100 0.04087 0.150 0.07387 0.200 0.11182 0.250 0.15355 0.300 0.19817 0.350 0.24498 0.400 0.29337 0.450 0.34278 0.500 0.39270

h: height; D: diameter; and A: area.Rules for using table: (1) Divide height of segment by the diameter; multiply the area in the table corresponding to the quotient, height/diameter, by the diameter squared. Whensegment exceeds a semicircle, its area is: area of circle minus the area of a segment whose height is the circle diameter minus the height of the given segment. (2) To find thediameter when given the chord and the segment height: the diameter= [( chord)2/height]+height.Source: Ref. [18]

R E B O I L E R S 10 / 453

Table 10.3 Guidelines for Sizing Steam and Condensate Nozzles

Shell OD (in.) Heat-transfer Nominal nozzle diameter (in.)area (ft2)

Steam Condensate

16 130 4 1.520 215 4 224 330450 6 330 5251065 68 3436 7351520 8 442 14002180 8 4

Source: Ref. [8]

10.3.9 Two-phase density calculationIn order to calculate the static head in the reboiler, the density of the two-phase mixture in theboiling region must be determined. For cross flow over tube bundles, this calculation is usuallymade using either the homogeneous model, Equation (9.51), or one of the methods for separatedflow in tubes, such as the Chisholm correlation, Equation (9.63). Experimental data indicate thatneither approach is particularly accurate [9], but there is no entirely satisfactory alternative. Thehomogeneous model is somewhat easier to use, but the Chisholm correlation will generally give amore conservative (larger) result for the static head.The following example illustrates the design procedure for kettle reboilers.

Example 10.2

96,000 lb/h of a distillation bottoms having the following composition will be partially vaporized ina reboiler:

Component Mole % Critical pressure (psia)

Propane 15 616.3i-butane 25 529.0n-butane 60 551.1

The stream will enter the reboiler as a (nearly) saturated liquid at 250 psia. The dew-point tem-perature of the stream at 250 psia is 205.6F. Saturated steam at a design pressure of 20 psia willbe used as the heating medium. The reboiler is to supply 48,000 lb/h of vapor to the distillationcolumn. The reboiler feed line will be approximately 23 ft long, while the vapor return line will havea total length of approximately 20 ft. The available elevation difference between the liquid level inthe column sump and the reboiler inlet is 9 ft. Physical property data are given in the following table.Design a kettle reboiler for this service.

Property Reboiler feed Liquid overflow Vapor return

T (F) 197.6 202.4 202.4H(Btu/lbm) 106.7 109.9 216.4CP (Btu/lbm F) 0.805 0.811 0.576k(Btu/h ft F) 0.046 0.046 0.014(cp) 0.074 0.074 0.0095(lbm/ft3) 28.4 28.4 2.76(dyne/cm) 3.64 3.59 Molecular weight 56.02 56.57 55.48

D E S I G N O F S H E L L-A N D-T U B E H E AT E X C H A N G E R S 5 / 233

Pn = 1.5 103NsG2n/s (laminar flow, Ren 100) (5.A.4)

In these equations, Ns is the number of shells connected in series.The shell-side pressure drop, excluding nozzle losses, is computed using the following equation:

Pf =f G2ds(nb + 1)2000Des

(5.A.5)

wherePf = pressure drop (Pa)

f = shell-side friction factor (dimensionless)G=mass flux= m/as (kg/s m2)as= flow area across tube bundle (m2)= dsC B/PT

ds= shell ID (m)C = clearance (m)B= baffle spacing (m)PT = tube pitch (m); replaced by PT /

2 for 45 tube layouts

nb= number of bafflesDe= equivalent diameter from Fig. 3.12 (m)s= fluid specific gravity (dimensionless)= viscosity correction factor = (/w)0.14 (dimensionless)

Appendix 5.B Maximum Tube-Side Fluid VelocitiesThe data presented here are from Bell and Mueller [3]. The maximum velocities are based onprevention of tubewall erosion and arematerial specific. They are intended to serve as a supplementto the general guideline of Vmax= 8 ft/s for liquids given in Section 5.7.4.Maximum velocities for water are given in Table 5.B.1. For liquids other than water, multiply the

values from the table by the factor (water/fluid)0.5.

Table 5.B.1 Maximum Recommended Velocities forWater in Heat-Exchanger Tubes

Tube material Vmax (ft/s)

Plain carbon steel 10Stainless steel 15Aluminum 6Copper 690-10 cupronickel 1070-30 cupronickel 15Titanium >50

For gases flowing in plain carbon steel tubing, the following equation can be used to estimate themaximum velocity:

Vmax =1800

(PM)0.5(5.B.1)

5 / 234 D E S I G N O F S H E L L-A N D-T U B E H E AT E X C H A N G E R S

whereVmax=maximum velocity (ft/s)

P = gas pressure (psia)M =molecular weight of gas

For tubing materials other than plain carbon steel, assume the maximum velocities are in the sameratio as given in Table 5.B.1 for water.For example, to estimate the maximum velocity for air at 50 psia flowing in aluminum tubes, first

calculate the velocity for plain carbon steel tubing using Equation 5.B.1:

(Vmax)cs =1800

(50 29)0.5 = 43.7 ft/s

Then multiply by the ratio (6/10) from Table 5.B.1 to obtain the velocity for aluminum tubing:

Vmax = 0.6 47.3 = 28.4 = 28 ft/s

Appendix 5.C Maximum Unsupported Tube LengthsIn order to prevent tube vibration and sagging, TEMA standards specify maximum unsupportedtube lengths for two groups of materials. Material group A consists of steel, steel alloys, nickel,nickel-copper alloys andnickel-chromium-steel alloys.Material groupBconsists of aluminumand itsalloys, copper and its alloys, and titanium alloys at their upper temperature limit. For tube diametersbetween 19 mm and 51mm, the standards are well-approximated by the following equations [11]:

Group A: maximum unsupported length (mm)= 52 Do(mm)+ 532 (5.C.1)Group B: maximum unsupported length (mm)= 46 Do(mm)+ 436 (5.C.2)These equations apply to un-finned tubes. The standards for finned tubes are more complicated,

but can be estimated by using the above equations with the tube OD replaced by the root-tubediameter. The standards also include temperature limits above which the unsupported length mustbe reduced [12]. For convenience, values computed fromEquations (5.C.1) and (5.C.2) are tabulatedbelow.

Table 5.C.1 Maximum Unsupported Straight Tube Lengths in Inches (mm)Tube OD Material group A Material group B

0.75 (19.1) 60 (1525) 52 (1315)0.875 (22.2) 66 (1686) 57 (1457)1.0 (25.4) 73 (1853) 63 (1604)1.25 (31.8) 86 (2186) 75 (1899)1.5 (38.1) 99 (2513) 86 (2189)2.0 (50.8) 125 (3174) 109 (2773)

The baffle spacing is generally restricted to be no greater than half the tabled values becausetubes in the baffle windows are supported by every other baffle. However, the inlet and outlet bafflespacings are often larger than the central baffle spacing. In this case, the central spacing mustsatisfy the following relation:

B tabled valuemax(Bin, Bout) (5.C.3)In practice, the actual unsupported tube length should be kept safely below (80% or less) the TEMAlimit.

D E S I G N O F S H E L L-A N D-T U B E H E AT E X C H A N G E R S 5 / 235

Appendix 5.D Comparison of Head Types for Shell-and-Tube Exchangers

Table 5.D.1 Comparison of Stationary Head Types

Head type Advantages Disadvantages

A, L (1) Tubesheet easily accessible by removing (1) Most expensive type except for Dchannel cover (2) Not well suited for high tube-side

(2) Head can be removed if unrestricted pressures; tube-side fluid can leak toaccess to tubesheet is required environment through gasket at tubesheet

(3) Type L rear head used only with fixedtubesheets

B, M (1) Low cost (1) Head must be disconnected from(2) Removal of head provides unrestricted process piping and removed to access

access to tubesheet tubesheet(3) Absence of channel cover eliminates (2) Not well suited for high tube-side

one external gasket where leakage to pressures; tube-side fluid can leak toenvironment can occur environment through gasket at

tubesheet(3) Type M rear head used only with fixed

tubesheets

C (1) Low cost (1) Head and tubesheet materials must be(2) Tubesheet easily accessed by removing compatible for welding

channel cover (2) All tube-side maintenance must be(3) Suitable for high pressures; channel done with channel in place

cover seal is the only external gasket (3) Used only with removable tube bundles

D (1) Least prone to leakage (1) Not cost effective unless tube-side(2) Best option when product of channel pressure is high

diameter and tube-side pressureexceeds about 86,000 in. psia

N (1) Least expensive (1) Head, tubesheet and shell materials(2) Tubesheet easily accessed by removing must be compatible for welding

channel cover (2) Used only with fixed tubesheets(3) Suitable for high pressures; channel (3) All tube-side maintenance must be

cover seal is the only external gasket done with channel in place

5 / 236 D E S I G N O F S H E L L-A N D-T U B E H E AT E X C H A N G E R S

Table 5.D.2 Comparison of Floating-Head Types

Head type Advantages Disadvantages

P (1) No internal gaskets where leakage (1) Shell-side fluid can leak through packingand fluid mixing can occur to environment

(2) Shell-side T (

RECOMMENDED GOOD PRACTICE SECTION 10

Fouling Resistances for Industrial Fluids

10-29 @Tubular Exchanger Manufacturers Association, Inc.

Oils: Fuel Oil #2 Fuel Oil #6 Transformer Oil Engine Lube Oil Quench Oil

0.002

0.005

0.001

0.001

0.004

Gases And Vapors: Manufactured Gas Engine Exhaust Gas Steam (Non-Oil Bearing) Exhaust Steam (Oil Bearing) Refrigerant Vapors (Oil Bearing) Compressed Air Ammonia Vapor COP Vapor Chlorine Vapor Coal Flue Gas Natural Gas Flue Gas

0.01 0

0.01 0

0.0005

0.0015-0.002

0.002

0.001 0.001

0.001

0.002

0.01 0

0.005

Liquids: Molten Heat Transfer Salts Refrigerant Liquids Hydraulic Fluid Industrial Organic Heat Transfer Media Ammonia Liquid Ammonia Liquid (Oil Bearing) Calcium Chloride Solutions Sodium Chloride Solutions COP Liquid Chlorine Liquid Methanol Solutions Ethanol Solutions Ethylene Glycol Solutions

0.0005

0.001

0.001

0.002

0.001

0.003

0.003 0.003

0.001

0.002

0.002

0.002

0.002

SECTION 10 RECOMMENDED GOOD PRACTICE

Fouling Resistances For Chemical Processing Streams

Fouling Resistances For Natural Gas-Gasoline Processing Streams - --

Gases And Vapors: Acid Gases Solvent Vapors Stable Overhead Products

@Tubular Exchanger Manufacturers Association, Inc.

0.002-0.003

0.001

0.001

Gases And Vapors: Natural Gas Overhead Products

Liquids:

0.001 -0.002

0.001 -0.002

MEA And DEA Solutions DEG And TEG Solutions Stable Side Draw And Bottom Product Caustic Solutions Vegetable Oils

0.002

0.002

0.001 -0.002

0.002

0.003

Liquids: Lean Oil Rich Oil Natural Gasoline And Liquified Petroleum Gases

0.002

0.001 -0.002

0.001 -0.002

RECOMMENDED GOOD PRACTICE SECTION 10

Fouling Resistances For Oil Refinery Streams

Crude And Vacuum Unit Gases And Vapors:

~

~

i

i

i i

Atmospheric Tower Overhead Vapors Light Naphthas Vacuum Overhead Vapors

@Tubular Exchanger Manufacturers Association, Inc. 10-31

0.001 0.001 0.002

Crude And Vacuum Liquids: Crude Oil

DRY

SALT*

DRY

SALT*

250 to 350 OF VELOCITY FTISEC

Oto250F VELOCITY FTJSEC

4

0.003

0.005

Cracking And Coking Unit Streams: Overhead Vapors Light Cycle Oil Heavy Cycle Oil Light Coker Gas Oil Heavy Coker Gas Oil Bottoms Slurry Oil (4.5 FtJSec Minimum) Light Liquid Products

0.002 0.002-0.003 0.003-0.004 0.003-0.004 0.004-0.005 0.003 0.002

SECTION 10 RECOMMENDED GOOD PRACTICE

Fouling Resistances For Oil Refinery Streams- continued

@Tubular Exchanger Manufacturers Association, Inc.

r Catalytic Reforming, Hydrocracking And Hydrodesulfurization Streams:

Reformer Charge Reformer Effluent Hydrocracker Charge And Effluent* Recycle Gas Hydrodesulfurization Charge And Effluent* Overhead Vapors Liquid Product Over 50 " A.P.I. Liquid Product 30 - 50 " A.P.I.

0.0015

0.0015

0.002

0.001

0.002

0.001

0.001

0.002 *Depending on charge, characteristics and storage history, charge resistance may be many times this value.

Light Ends Processing Streams: Overhead Vapors And Gases Liquid Products Absorption Oils Alkylation Trace Acid Streams Reboiler Streams

0.001

0.001

0.002-0.003

0.002

0.002-0.003

Lube Oil Processing Streams: Feed Stock Solvent Feed Mix Solvent Extract* Raff inate Asphalt Wax Slurries* Refined Lube Oil *Precautions must be taken to prevent wax deposition on cold tube walls.

0.002

0.002 0.001

0.003

0.001

0.005

0.003

0.001

Visbreaker: Overhead Vapor Visbreaker Bottoms

0.003

0.010

Naphtha Hydrotreater: Feed Effluent Naphthas Overhead Vapors

0.003

0.002

0.002

0.001 5

RECOMMENDED GOOD PRACTICE SECTION 10

Fouling Resistances for Oil Refinery Streams - continued

I

Catalytic Hydro Desulfurizer:

Fouling Resistances For Water

@Tubular Exchanger Manufacturers Associatson, Inc.

Charge Effluent H.T. Sep. Overhead Stripper Charge Liquid Products

I Temperature Of Heating Medium Temperature Of Water

Sea Water Brackish Water Cooling Tower And Artificial Spray Pond:

Treated Make Up Untreated

City Or Well Water River Water:

Minimum Average

Muddy Or Silty Hard (Over 15 GrainsIGal.) Engine Jacket Distilled Or Closed Cycle Condensate Treated Boiler Feedwater Boiler Blowdown

0.004-0.005

0.002

0.002

0.003

0.002

If the heating medium temperature is over 400 " F and the cooling medium is known to scale, these ratings should be modified accordingly.

10-33

HF Alky Unit:

Up To 240 " F 125" F

Water Velocity FtJSec

Alkylate, Deprop. Bottoms, Main Fract. Overhead Main Fract. Feed All Other Process Streams

3 and Less 0.0005

0.002

240 to 400 " F Over 125 " F

Water Velocity Ft/Sec

0.003

0.002

Over 3 0.0005

0.001

3 and Less 0.001

0.003

0.001

0.003 0.001

Over 3 0.001

0.002

0.001

0.003 0.001

0.002

0.005 0.002

0.002

0.003

0.003

0.005

0.001

0.002

0.003

0.003

0.003

0.001

0.002

0.004 0.002

0.001

0.002

0.002

0.003 0.001

0.003

0.004

0.004

0.005

0.001

0.0005

0.001

0.002

0.0005 0.001

0.002

0.0005

0.001

0.002

0.0005

0.0005

0.002

3 / 88 H E AT E X C H A N G E R S

may be removable for ease of cleaning and replacement (floating-head or U-tube exchanger). Inaddition, a number of different head and shell designs are commercially available as shown inFigure 3.4.TheTubularExchangerManufacturersAssociation (TEMA)employs a three-letter code to specify

the front-end, shell, and rear-end types. For example, a fixed tube-sheet type BEM exchanger is

FRONT END STATIONARY HEAD TYPES SHELL TYPES

REAR END HEAD TYPES

CHANNEL AND REMOVABLE COVER

ONE PASS SHELL

TWO PASS SHELL WITH LONGITUDINAL BAFFLE

FIXED TUBESHEET LIKE "B" STATIONARY HEAD

FIXED TUBESHEET LIKE "N" STATIONARY HEAD

FIXED TUBESHEET LIKE "A" STATIONARY HEAD

BONNET (INTEGRAL COVER) SPLIT FLOW

OUTSIDE PACKED FLOATING HEAD

FLOATING HEAD WITH BACKING DEVICE

PULL THROUGH FLOATING HEAD

U-TUBE BUNDLE

REMOVABLE TUBE

BUNDLE ONLY

CHANNEL INTEGRAL WITH TUBE- SHEET AND REMOVABLE COVER

CHANNEL INTEGRAL WITH TUBE- SHEET AND REMOVABLE COVER

SPECIAL HGIH PRESSURE CLOSURE CROSS FLOW

KETTLE TYPE REBOILER

DIVIDED FLOW

DOUBLE SPLIT FLOW

EXTERNALLY SEALED FLOATING TUBE SHEET

A

B

C

N

D X

K

J

H

G

F

E L

M

N

P

S

T

U

W

Figure 3.4 TEMA designations for shell-and-tube exchangers (Source: Ref. [5]).

Datos UtilesPginas desde1st editionHeat Exchanger Design HandbookPginas desde1st editionHeat Exchanger Design Handbook-2Pginas desdeB.W.G. ChartPginas desdeProcess-Heat-Transfer-Principles-and-Applications-by-R-W-SerthPginas desdeProcess-Heat-Transfer-Principles-and-Applications-by-R-W-Serth-2Pginas desdeProcess-Heat-Transfer-Principles-and-Applications-by-R-W-Serth-4Pginas desdeProcess-Heat-Transfer-Principles-and-Applications-by-R-W-Serth-5Pginas desdeProcess-Heat-Transfer-Principles-and-Applications-by-R-W-Serth-6Pginas desdeProcess-Heat-Transfer-Principles-and-Applications-by-R-W-Serth-7Pginas desdeProcess-Heat-Transfer-Principles-and-Applications-by-R-W-Serth-8Pginas desdeTEMA_9TH_EDITION_2007Process-Heat-Transfer-Principl-and-Applications-by-R-W-Serth 103Pgina en blanco